Measurement-while-drilling assembly using real-time toolface oriented measurements

ABSTRACT

This invention provides a measurement-while-drilling (MWD) downhole assembly for use in drilling boreholes which utilizes directional formation evaluation devices on a rotating assembly in conjunction with toolface orientation sensors. The data from the toolface orientation sensors are analyzed by a processor and toolface angle measurements are determined at defined intervals. Formation evaluation sensors operate substantially independently of the toolface orientation sensors and measurements of the formation evaluation sensors are analyzed in combination with the determined toolface angle to obtain formation parameters.

CROSS REFERENCES TO RELATED APPLICATIONS

This application claims priority from U.S. Provisional PatentApplication Ser. No. 60/399,741 filed on Jul. 30, 2002 and United StatesProvisional Patent Application Ser. No. 60/408,308 filed on Sep. 5,2002.

FIELD OF THE INVENTION

This invention relates generally to assemblies for making toolfaceoriented measurements within a borehole and processing of suchmeasurements to determine parameters of interest of materials around theborehole. The invention is described in the context ofmeasurement-while-drilling applications for obtaining formationproperties but the principles of analysis are equally applicable tomeasurements made with a wireline.

BACKGROUND OF THE INVENTION

To obtain hydrocarbons such as oil and gas, wellbores (also called theboreholes) are drilled by rotating a drill bit attached at the end of adrilling assembly generally called the “bottom hole assembly” or the“drilling assembly.” A large portion of the current drilling activityinvolves drilling highly deviated or substantially horizontal wellboresto increase the hydrocarbon production and/or to withdraw additionalhydrocarbons from the earth's formations. The wellbore path of suchwells is carefully planned before drilling such wellbores using seismicmaps of the earth's subsurface and well data from previously drilledwellbores in the associated oil fields. Due to the very high cost ofdrilling such wellbores and the need precisely to place such wellboresin the reservoirs, it is essential continually to determine the positionand direction of the drilling assembly and thus the drill bit duringdrilling of the wellbores. Such information is used, among other things,to monitor and adjust the drilling direction of the wellbores.

In drilling assemblies used until recently, the directional packagecommonly includes a set of accelerometers and a set of magnetometers,which respectively measure the earth's gravity and magnetic field. Thedrilling assembly is held stationary during the taking of themeasurements from the accelerometers and the magnetometers. The toolfaceand the inclination angle are determined from the accelerometermeasurements. The azimuth is then determined from the magnetometermeasurements in conjunction with the tool face and inclination angle.

The earth's magnetic field varies from day to day, which causescorresponding changes in the magnetic azimuth. The varying magneticazimuth compromises the accuracy of the position measurements whenmagnetometers are used. Additionally, it is not feasible to measure theearth's magnetic field in the presence of ferrous materials, such ascasing and drill pipe. Gyroscopes measure the rate of the earth'srotation, which does not change with time nor are the gyroscopesadversely affected by the presence of ferrous materials. Thus, in thepresence of ferrous materials the gyroscopic measurements can providemore accurate azimuth measurements than the magnetometer measurements.U.S. Pat. No. 6,347,282 to Estes et al having the same assignee as thepresent application and the contents of which are fully incorporatedherein by reference, discloses a measurement-while-drilling (MWD)downhole assembly for use in drilling boreholes that utilizesgyroscopes, magnetometers and accelerometers for determining theborehole inclination and azimuth during the drilling of the borehole.The downhole assembly includes at least one gyroscope that is rotatablymounted in a tool housing to provide signals relating to the earth'srotation. A device in the tool can rotate the gyroscope and othersensors on the tool at any desired angle. This ability to rotate thesensors is important in determining bias in the sensors and eliminatingthe effects of the bias.

U.S. Pat. No. 5,091,644 to Minette having the same assignee as thepresent application teaches a method for analyzing data from ameasurement-while-drilling (MWD) gamma ray density logging tool whichcompensates for rotations of the logging tool (along with the rest ofthe drillstring) during measurement periods. In accordance with themethod disclosed therein, the received signal is broken down into aplurality of sections. In a preferred embodiment, the Minette inventioncalls for the breaking of the signal from the formation into fourdifferent sections: top, bottom, right, left. As the tool rotates, itpasses through these four quadrants. Each time it passes a boundary, acounter is incremented, pointing to the next quadrant. This allows fordividing the data into four spectra for each detector. Each of thesefour spectra will be obtained for ¼th of the total acquisition time.

U.S. Pat. No. 6,307,199 to Edwards et al teaches the use of a densitygamma ray logging device in which data from different “azimuthal”sectors are combined to give an interpretation of formation dip. Theprimary emphasis in both the Minette and Edwards patent is to correctthe density measurements for the effects of standoff; the sensorsthemselves are not specifically designed for “azimuthal” sensitivity.U.S. Pat. No. 6,215,120 to Gadeken et al. discloses the use of“azimuthally” focused gamma ray sensors on a logging tool for detecting“azimuthal” variations in the gamma ray emission from earth formations.

We digress briefly on a matter of terminology. In surveying, the term“azimuth” usually refers to an angle in a horizontal plane, usuallymeasured from north: when referenced to magnetic north, it may be calledmagnetic azimuth and when referenced to true north, it is usually simplytermed azimuth. It would be clear based on this definition that allmeasurements made in a highly deviated borehole or a horizontal boreholewould be made with substantially the same azimuth. Accordingly, in thepresent application, we use the more accurate term “tool face angle” todefine a relative orientation in a plane orthogonal to the boreholeaxis. With this definition, the Minette, Edwards and Gadeken patents arereally making measurements over a variety of tool face angles.

Common to the Minette, Edwards and Gadeken patents is the use of acontroller that keeps track of the rotating sensor assembly and controlsthe acquisition of data based on sector boundaries in the tool faceangle. While this may not be difficult to do for the case of a singledirectionally sensitive sensor, the problem becomes much morecomplicated when a plurality of different types of sensors are conveyedas part of a bottom hole assembly. It is difficult, if not impossible,for a single controller to keep track of a plurality of sensorassemblies during rotation of the downhole assembly and control theoperation of a plurality of assemblies. It would be desirable to have anapparatus and a method that efficiently controls data acquisition andpossibly processing with a plurality of rotating sensors in a downholedevice. The present invention satisfies this need.

SUMMARY OF THE INVENTION

One embodiment of the present invention includes a rotatable downholeassembly adapted for conveying in a borehole and determining a parameterof interest of a medium near to the borehole. The downhole assemblyincludes a first sensing device such as a gyroscope, a magnetometer,and/or an accelerometer, for providing a measurement indicative of thetoolface angle of the downhole assembly, and an associated processor.The downhole assembly also includes a directional evaluation device forproviding measurements indicative of a parameter of interest of themedium. The directional evaluation device is associated with a secondprocessor. The first processor provides processed data about thetoolface orientation to a common bus operatively connected to the firstprocessor and the second processor. In a preferred embodiment of theinvention, a gyroscope is used to provide information about the locationof the assembly. The assembly may be conveyed on a drillstring, coiledtubing or on a wireline.

In a preferred embodiment of the invention, the directional device is aformation evaluation device. One or more gamma ray sensors may be used.The formation evaluation device may be operated independently of theorientation sensor. With this arrangement, a plurality of formationevaluation sensors may be used. Subsequent processing relates themeasurements of the formation evaluation sensors to toolface angle andprovides information about downhole parameters.

BRIEF DESCRIPTION OF THE DRAWINGS

For detailed understanding of the present invention, references shouldbe made to the following detailed description of the preferredembodiment, taken in conjunction with the accompanying drawings, inwhich like elements have been given like numerals, wherein:

FIG. 1 (prior art) shows a schematic diagram of a drilling system thatincludes the apparatus of the current invention in ameasurement-while-drilling embodiment;

FIG. 2 a, 2 b (prior art) shows a schematic diagram of a portion of thebottomhole assembly with a set of gyroscopes and a corresponding set ofaccelerometers according to a preferred embodiment of the presentinvention;

FIG. 3 shows an orientation sensor assembly and a dual detector gammaray sensor;

FIG. 4 shows the tool face angle as a function of time;

FIG. 5 shows an azimuthal display of time ticks;

FIG. 6 illustrates the azimuthal resolution of an exemplary gamma raydirectional logging tool;

FIG. 7 illustrates the configuration of the apparatus of the presentinvention for determining relative angle with respect to a bed boundary;

FIG. 8 illustrates the directional measurements made by the apparatus asshown in FIG. 7;

FIG. 9 illustrates a flow chart of the method used for characterizingthe toolface-angle dependent data in a series expansion; and

FIG. 10 shows an example of processing of the data using the method ofthe present invention

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

The present invention is described with reference to a drillingassembly, although many of the methods of the present invention are alsoapplicable with logging tools conveyed on a wireline and may also beused in cased boreholes. FIG. 1 shows a schematic diagram of anexemplary drilling system 10 such as that disclosed by Estes. Thedrilling system has a bottom hole assembly (BHA) or drilling assembly 90that includes gyroscope. For some of the applications of the presentinvention, a gyroscope is not essential. The BHA 90 is conveyed in aborehole 26. The drilling system 10 includes a conventional derrick 11erected on a floor 12 which supports a rotary table 14 that is rotatedby a prime mover such as an electric motor (not shown) at a desiredrotational speed. The drill string 20 includes a tubing (drill pipe orcoiled-tubing) 22 extending downward from the surface into the borehole26. A drill bit 50, attached to the drill string 20 end, disintegratesthe geological formations when it is rotated to drill the borehole 26.The drill string 20 is coupled to a drawworks 30 via a kelly joint 21,swivel 28 and line 29 through a pulley (not shown). Drawworks 30 isoperated to control the weight on bit (“WOB”), which is an importantparameter that affects the rate of penetration (“ROP”). A tubinginjector 14 a and a reel (not shown) are used as instead of the rotarytable 14 to inject the BHA into the wellbore when a coiled-tubing isused as the conveying member 22. The operations of the drawworks 30 andthe tubing injector 14 a are known in the art and are thus not describedin detail herein.

During drilling, a suitable drilling fluid 31 from a mud pit (source) 32is circulated under pressure through the drill string 20 by a mud pump34. The drilling fluid passes from the mud pump 34 into the drill string20 via a desurger 36 and the fluid line 38. The drilling fluid 31discharges at the borehole bottom 51 through openings in the drill bit50. The drilling fluid 31 circulates uphole though the annular space 27between the drill string 20 and the borehole 26 and returns to the mudpit 32 via a return line 35 and drill cutting screen 85 that removes thedrill cuttings 86 from the returning drilling fluid 31 b. A sensor S₁ inline 38 provides information about the fluid flow rate. A surface torquesensor S₂ and a sensor S₃ associated with the drill string 20respectively provide information about the torque and the rotationalspeed of the drill string 20. Tubing injection speed is determined fromthe sensor S₅, while the sensor S₆ provides the hook load of the drillstring 20.

In some applications the drill bit 50 is rotated by only rotating thedrill pipe 22. However, in many other applications, a downhole motor 55(mud motor) is disposed in the drilling assembly 90 to rotate the drillbit 50 and the drill pipe 22 is rotated usually to supplement therotational power, if required, and to effect changes in the drillingdirection. In either case, the ROP for a given BHA largely depends onthe WOB or the thrust force on the drill bit 50 and its rotationalspeed.

The mud motor 55 is coupled to the drill bit 50 via a drive disposed ina bearing assembly 57. The mud motor 55 rotates the drill bit 50 whenthe drilling fluid 31 passes through the mud motor 55 under pressure.The bearing assembly 57 supports the radial and axial forces of thedrill bit 50, the downthrust of the mud motor 55 and the reactive upwardloading from the applied weight on bit. A lower stabilizer 58 a coupledto the bearing assembly 57 acts as a centralizer for the lowermostportion of the drill string 20.

A surface control unit or processor 40 receives signals from thedownhole sensors and devices via a sensor 43 placed in the fluid line 38and signals from sensors S₁-S₆ and other sensors used in the system 10and processes such signals according to programmed instructions providedto the surface control unit 40. The surface control unit 40 displaysdesired drilling parameters and other information on a display/monitor42 that is utilized by an operator to control the drilling operations.The surface control unit 40 contains a computer, memory for storingdata, recorder for recording data and other peripherals. The surfacecontrol unit 40 also includes a simulation model and processes dataaccording to programmed instructions. The control unit 40 is preferablyadapted to activate alarms 44 when certain unsafe or undesirableoperating conditions occur.

The BHA may also contain formation evaluation sensors or devices fordetermining resistivity, density and porosity of the formationssurrounding the BHA. A gamma ray device for measuring the gamma rayintensity and other nuclear and non-nuclear devices used asmeasurement-while-drilling devices are suitably included in the BHA 90.As an example, FIG. 1 shows a resistivity measuring device 64. Itprovides signals from which resistivity of the formation near or infront of the drill bit 50 is determined. The resistivity device 64 hastransmitting antennae 66 a and 66 b spaced from the receiving antennae68 a and 68 b. In operation, the transmitted electromagnetic waves areperturbed as they propagate through the formation surrounding theresistivity device 64. The receiving antennae 68 a and 68 b detect theperturbed waves. Formation resistivity is derived from the phase andamplitude of the detected signals. The detected signals are processed bya downhole computer 70 to determine the resistivity and dielectricvalues.

An inclinometer 74 and a gamma ray device 76 are suitably placed alongthe resistivity measuring device 64 for respectively determining theinclination of the portion of the drill string near the drill bit 50 andthe formation gamma ray intensity. Any suitable inclinometer and gammaray device, however, may be utilized for the purposes of this invention.In addition, position sensors, such as accelerometers, magnetometers ora gyroscopic devices may be disposed in the BHA to determine the drillstring azimuth, true coordinates and direction in the wellbore 26. Suchdevices are known in the art and are not described in detail herein.

In the above-described configuration, the mud motor 55 transfers powerto the drill bit 50 via one or more hollow shafts that run through theresistivity measuring device 64. The hollow shaft enables the drillingfluid to pass from the mud motor 55 to the drill bit 50. In an alternateembodiment of the drill string 20, the mud motor 55 may be coupled belowresistivity measuring device 64 or at any other suitable place. Theabove described resistivity device, gamma ray device and theinclinometer are preferably placed in a common housing that may becoupled to the motor. The devices for measuring formation porosity,permeability and density (collectively designated by numeral 78) arepreferably placed above the mud motor 55. Such devices are known in theart and are thus not described in any detail.

As noted earlier, a large portion of the current drilling systems,especially for drilling highly deviated and horizontal wellbores,utilize coiled-tubing for conveying the drilling assembly downhole. Insuch application a thruster 71 is deployed in the drill string 90 toprovide the required force on the drill bit. For the purpose of thisinvention, the term weight on bit is used to denote the force on the bitapplied to the drill bit during the drilling operation, whether appliedby adjusting the weight of the drill string or by thrusters. Also, whencoiled-tubing is utilized the tubing is not rotated by a rotary table,instead it is injected into the wellbore by a suitable injector 14 awhile the downhole motor 55 rotates the drill bit 50.

A number of sensors are also placed in the various individual devices inthe drilling assembly. For example, a variety of sensors are placed inthe mud motor power section, bearing assembly, drill shaft, tubing anddrill bit to determine the condition of such elements during drillingand to determine the borehole parameters. The preferred manner ofdeploying certain sensors in drill string 90 will now be described. Theactual BHA utilized for a particular application may contain some or allof the above described sensors. For the purpose of this invention anysuch BHA could contain one or more gyroscopes and a set ofaccelerometers (collectively represented herein by numeral 88) at asuitable location in the BHA 90. A preferred configuration of suchsensors is shown in FIG. 2 a.

FIG. 2 is a schematic diagram showing a sensor section 200 containing agyroscope 202 and a set of three accelerometers 204 x, 204 y and 204 zdisposed at a suitable location in the bottomhole assembly (90 inFIG. 1) according to one preferred embodiment of the present invention.The gyroscopes 202 may be a single axis gyroscope or a two-axisgyroscope. In vertical and low inclination weilbores, an x-axis and ay-axis gyroscope are deemed sufficient for determining the azimuth andtoolface with respect to the true north. The configuration shown in FIG.2 utilizes a single two-axis (x-axis and y-axis) gyroscope that providesoutputs corresponding to the earth's rate of rotation in the two axisperpendicular to the borehole axis or the bottomhole assemblylongitudinal axis, referred to herein as the z-axis. The sensor 202 thusmeasures the earth's rotation component in the x-axis and y-axis. Theaccelerometers 204 x, 204 y and 204 z measure the earth's gravitycomponents respectively along the x, y, and z axes of the bottomholeassembly 90.

The gyroscope 202 and accelerometers 204 x-204 z are disposed in arotating chassis 210 that rotates about the radial bearings 212 a-212 bin a fixed or non-rotating housing 214. An indexing drive motor 216coupled to the rotating chassis 210 via a shaft 218 can rotate thechassis 210 in the bottomhole assembly 90 about the z-axis, thusrotating the gyroscopes 202 from one mechanical position to anotherposition by any desired rotational angle. A stepper motor is preferredas the indexing drive motor 216 because stepper motors are precisiondevices and provide positive feedback about the amount of rotation. Anyother mechanism, whether electrically-operated, hydraulically-operatedor by any other desired manner, may be utilized to rotate the gyroscopeswithin the bottomhole assembly 90. The gyroscope 202 may be rotated froman initial arbitrary position to a mechanical stop (not shown) in thetool or between two mechanical stops or from an initial peak measurementto a second position as described later. The rotational anglecorresponding to a particular axis is selectable.

Although FIG. 2 shows a single two axis gyroscope, a separate gyroscopemay be utilized for each axis. A wiring harness 226 provides power tothe gyroscope 202 and accelerometers 204 x, 204 y, 204 z. The wiringharness 226 transmits signals from the gyroscope and accelerometers tothe processor in the bottomhole assembly 90. Similarly, a suitablewiring harness 220 provides power and signal linkage to the steppermotor 216 and additional downhole equipment. A spring loaded torquelimiter 240 may be used to prevent inertial loading caused bydrillstring rotation from damaging the gearbox of the stepper motor 216.

In addition a second two-axis (x-axis and z-axis) gyroscope 230 may berotatably mounted in the bottomhole assembly 90 in a rotating chassis orin any other manner to measure the rate of rotation in the z-axis andthe x-axis, as shown in FIG. 2 b. The sensor 230 could be rotated aboutthe y-axis using a bevel gear 242 and a shaft linkage 244 to therotating chassis 210, thus eliminating the need for an additional motor.The wiring harness 244 for the y-axis gyro 230 must be spooled aroundthe gyro to accommodate the space available in a small diameter housing.

Turning now to FIG. 3, details of the gamma ray sensor 78 mentionedabove are shown. A preferred gamma ray logging device comprising twogamma ray sensors 252 a, 252 b is shown along with an orientation sensorassembly 250. The orientation sensor assembly may include all theelements of the gyro-MWD device described above, but the some aspects ofthe method of the present invention may also be practiced with onlyorientation sensors such as accelerometers and or magnetometers. FIG. 3also shows a processor 251 associated with the orientation/navigationsensor assembly. In a preferred embodiment of the invention, the primarypurpose of the processor 251 is to process signals from theorientation/navigation sensor assembly 250. Also shown in FIG. 3 is aprocessor 254 associated with the gamma ray sensors. It should also benoted that for certain uses of the method of the present invention, onlyone gamma ray sensor may be sufficient.

In a preferred embodiment of the invention, two gamma ray detectorsspaced 180° apart are used. When two detectors are used, the counts fromthe two may be combined. In a preferred embodiment of the invention, theprocessors 251 and 254 operate at a clock frequency of approximately 60Hz. The counts from the gamma ray sensor(s) are accumulated at a samplerate of 16.67 ms. This is done regardless of the actual rotation speedof the assembly. Other sample rates may be used, but a requirement isthat it be fixed.

The “tick” size is defined as the change in the toolface angle over onetime sample interval. The tick size increases with rotation speed andlimits the resolution of the method and apparatus of the presentinvention. However, as discussed below, the effect of tick size can besubstantially eliminated.

In a preferred embodiment of the invention, each detector has anintrinsic resolution of ±35°. This is determined by the shielding thatis provided for the gamma ray detectors. In the method of the presentinvention, the data are binned into finite bins with a defined angularsize, preferably 45°. The finite bin size further limits the angularresolution. Increasing the number of bins improves the angularresolution up to a point beyond which the poor statistics of gamma raycounts degrade the measurements.

An important feature of the apparatus of the present invention is acommon bus, designated generally as 260. The various processors (251 and254 in FIG. 4) output their processed data to the bus. The bus is alsoconnected to a telemetry device (not.shown) at a suitable location fortwo-way communication with the surface controller and receiving datafrom the surface. In an alternate embodiment of the present invention,two-way communication between the bottom hole assembly and the surfacecontroller may be accomplished using flowable devices carried by thedrilling fluid. Such flowable devices are taught in U.S. Pat. No.6,443,228) to Aronstam et al, having the same assignee as the presentapplication and the contents of which are fully incorporated herein byreference.

The advantage of having a common bus 260 is that the processor 251 canprocess data from the orientation/navigation sensor independently of theprocessing of data from the gamma ray sensor(s) 252 a, 252 b by theprocessor 254. As would be known to those versed in the art, it is notuncommon for the rotation speed to be non-uniform. The processor 251continues to process the data from the orientation sensor and outputsthe toolface angle as a function of time to the bus 260. An advantage ofhaving the common bus is that any additional directional evaluationdevices could also operate independently of the orientation/navigationsensor assembly. As a result of this independent operation, a plot ofthe toolface angle as a function of sample number such as that shown inFIG. 4 may be obtained. The manner in which this is obtained isdiscussed next.

Turning now to FIG. 5, eight sectors of tool face angles are shown,numbered 0, 1, 2, 3, 4, 5, 6 and 7. The use of eight sectors is optionaland more or fewer sectors may be used. Also shown are ticks labeled as301 a, 301 b, 301 c . . . 301 n. As noted above, the particularpositions of the ticks are not known at the time the gamma ray sensor ismaking measurements—these are determined after the fact usinginformation from the orientation sensors. The provide values of thetoolface angle at discrete times. The toolface angle at intermediatetimes may be determined by interpolation; in a preferred embodiment ofthe invention, linear interpolation is used.

There are a number of factors that limit the resolution of the method ofthe present invention in terms of tool face angle. The first limit isdetermined by the static resolution of the gamma ray sensors. The staticresolution is the ability to resolve two point sources of gamma rays andis defined as the resolution that is achievable with an infinitely longacquisition time (i.e., so that statistical fluctuations areeliminated). FIG. 6 shows an example of a tool response function as afunction of toolface angle. Typically, it is a Gaussian function with ahalf-width determined by the shielding provided for the detectors.

The actual resolution is obtained by convolving the static resolutionwith a bin window and the tick window; the actual resolution is thuspoorer than the static resolution. Increasing the number of bins whilemaintaining the acquisition time T_(acq) constant does not increase theoverall resolution due to the fact that the statistical fluctuationswithin a bin become larger.

Turning now to FIG. 7, an example of the use of the method of thepresent invention is shown. Shown is the apparatus of the presentinvention 401 including at least one gamma ray detector with region ofsensitivity in the “up” and “down” direction shown by 409, 411. Forsimplifying the illustration, in FIG. 7 it is assumed that the normal tothe boundary 403 between formations 405 and 407 lies in a vertical planeso that “up” and “down” directions in FIG. 7 correspond to a combinationof sectors (0,7) and (3,4) in FIG. 5 respectively. The at least onegamma ray detector could comprise a pair of detectors. The data receivedby the at least one detector can then be processed to get gamma raycounts in the “up” and “down” directions respectively. When only onedetector is use, then the combination of measurements from, say sectors0 and 7 (see FIG. 5) is an “up” measurement while the measurements fromsectors 3 and 4 give a “down” measurement. When two detectors are used,their respective measurements in the “up” and “down” directions may becombined to improve the signal to noise ratio.

The apparatus is shown crossing the bed boundary 403 between two earthformations 405, 407. For illustrative purposes, assume that formation405 comprises a shale while 407 comprises a sand. For the configurationshown, the “up” gamma ray count will be greater than the “down” gammaray count. The increased count is due to the fact that the gamma raysensors have a limited azimuthal sensitivity and the potassium presentin the shale is a significant source of gamma rays.

By measuring both the “up” and “down” gamma ray counts as a function ofdepth, a plot shown in FIG. 8 results. Shown are the measurements madeby the “up” and “down” gamma ray sensors. The abscissa is the boreholedepth (actual depth, not true vertical depth) and the ordinate is thegamma ray count. In an optional embodiment of the invention, the rate ofpenetration (ROP) of the assembly in the borehole is determined usingsignals from the axial component accelerometer. Such a method isdisclosed in U.S. patent application Ser. No. 10/167,332 of Dubinsky etal, filed on 11 Jun. 2002 and the contents of which are fullyincorporated herein by reference. However, any suitable method fordetermining the ROP may be used.

The horizontal separation between the two curves is an indication of therelative angle at which the borehole crosses the bed boundary: thelarger the separation, the smaller the angle. Using knowledge of thetool response function, this angle can be determined.

In general, however, bed boundary may have an arbitrary orientation andthe maximum gamma ray count need not correspond to the “up” direction ofthe tool (sectors 0,7 in FIG. 5). The gamma ray count Ψ in a deviatedborehole as a function of the toolface angle φ can be approximated bythe function $\begin{matrix}{\Psi^{M} \approx {\sum\limits_{m = 0}^{M}{\Psi_{m}{\cos\quad\left\lbrack {m\left( {\phi - \phi_{0}} \right)} \right\rbrack}}}} & (1)\end{matrix}$Such a function satisfies two requirements of the gamma ray count: itmust be a periodic function with a period of 360°, and it must besymmetric with respect to the angle Φ₀ which is the toolface angle atwhich the detector is closest to a bed boundary. Note that the exampleof FIGS. 7 and 8 is a special case when the normal to the bed boundaryis in a vertical plane. It should also be noted that proximity to a bedboundary is not the only cause that will produce a variation of the formgiven by eq. (1); a similar results follows from a radial fractureextending out from the borehole.

To reconstruct the distribution with M terms, it is necessary to havethe number of bins of data N_(bins)>2(−1)+1. Hence to determine a threeterm expansion in eq. (1), at least 5 bins are necessary.

Turning next to FIG. 9, the method of the present invention isillustrated by the flow chart. Starting at 501, a model with M=0 isdefined, i.e., there is no variation with toolface angle of the gammaray count. This corresponds to a model in whichΨ=Const=Ψ₀  (2)A check is made to see if, based on the number of data points, theobservations can be adequately described by a constant 505 to within adefined probability. If the answer is “yes”, then the process terminatesand there is no variation with toolface angle of the data.

If the answer at 505 is “No”, then M is incremented 507 and a two termexpansion is made. This requires determination of the angle Φ₀. A firstestimate of the angle Φ₀ is obtained as the average of the data$\begin{matrix}{{\hat{\phi}}_{o} = {\frac{\sum\limits_{k = 1}^{N_{bins}}{n_{k}\phi_{k}}}{\sum\limits_{k = 1}^{N_{bins}}n_{k}}.}} & (3)\end{matrix}$The data are then rotated about the angle estimated from eq. (3) and atwo term fit is made to obtain Ψ₀ and Ψ₁ according to eq. (1). Keepingthese determined values of Ψ₀ and Ψ₁, a new estimate of Φ₀ is made. Acheck is again made of the goodness of fit 505 and again, if the fit isgood enough. the process terminates 509 and if the fit is not goodenough, an additional term is added to the curve fitting.

In order to improve the statistics on the measurements, averaging of themeasurements over a depth window may also be used. As noted above, themethod of Dubinsky discloses a method of using an axial accelerometerfor determining the depth of the tool In the present invention, themethod of Dubinsky is preferred for determining the depth of theassembly and defining the depth window over which averaging may be done,although other methods for depth determination may be used.

In most situations, gamma ray data will not have the necessaryresolution to use the higher order terms of the expansion given by eq.(1). Hence in a preferred embodiment of the invention, only a singleterm of the expansion given by eq. (1) is used. The method illustratedin FIG. 9 may be used for processing of image data. This is illustratedin FIGS. 10 a, 10 b.

Shown in FIG. 10 a are raw data acquired downhole. The vertical axisrepresents time (or depth) and the horizontal axis shows the sectors. Inthis particular example, eight sectors were used. The display may be acolor display or may be a black and white display of the gamma raycounts as a function of time (or depth) and the azimuth (sector).Following the curve fitting (using the cosine distributions as discussedabove) of the data at a selected time (or depth), partially processeddata (and a partially processed image), not shown, may be obtained. Thepartially processed data are than low pass filtered in the verticaldirection (time or depth). The filtered image may be quantized intodifferent levels and the resulting image displayed on a color display ora gray scale. This may be referred to as a processed image. An exampleof this is shown in FIG. 10 b. Also shown in FIG. 10 b are contours suchas 601 a, 601 b, 601 c . . . 601 n. In a display such as FIG. 10 b,these contours represent dipping boundaries that intersect the boreholeat an angle.

The method of the present invention has been discussed above withrespect to a gamma ray logging tool. However, the method of the presentinvention may also be used with any kind of logging tool having asensitivity that is dependent upon the toolface angle. This includesresistivity sensors with transverse induction coils such as thatdescribed in U.S. Pat. No. 6,147,496 of Strack et al. A plurality ofdirectional sensors may be used, each of which preferably has its ownassociated processor connected to the common bus.

The method of the present invention may also be used with wirelinelogging tools. When used with wireline tools, a motor is needed forrotating the assembly through different toolface angles so as to provideadequate sampling over the circumference of the borehole. The wirelinetools may be run open hole or, in case of certain types of sensors suchas gamma ray sensor, in cased hole. A slickline sensor assembly may alsobe used within a drillstring for some types of measurements.

While the foregoing disclosure is directed to the preferred embodimentsof the invention, various modifications will be apparent to thoseskilled in the art. It is intended that all variations within the scopeand spirit of the appended claims be embraced by the foregoingdisclosure.

1.-17. (canceled)
 18. A method of determining a parameter of interest ofa medium proximate to a borehole using a rotating downhole assembly insaid borehole, the method comprising: (a) obtaining information about atool-face angle of the assembly during rotation thereof; (b) using adirectionally sensitive evaluation device for obtaining measurementsindicative of the parameter of interest, said measurements beingobtained separately over a plurality of specified time intervals; and(c) . representing the directionally sensitive measurements by a seriesexpansion that includes a sinusoidal variation with the toolface angle.19. The method of claim 18 wherein obtaining said information about saidtool face angle further comprises: (i) using a navigation assemblyincluding a first sensing device that is at least one of (A) agyroscope, (B) a magnetometer, and, (C) an accelerometer, for providinga measurement indicative of said toolface angle; and (ii) using aprocessor associated with the navigation assembly for determining saidtoolface angle over said time intervals.
 20. The method of claim 19wherein said rotating downhole assembly further comprises a drill bitfor penetrating a formation, the method further comprising using atleast one of (I) said gyroscope, and, (II) an accelerometer, fordetermining a rate of penetration (ROP) of said downhole assembly. 21.(canceled)
 22. The method of claim 18 wherein said series expansionfurther includes a sinusoidal variation of twice said tool face angle.23. The method of claim 18 wherein said directional evaluation devicefurther comprises at least one gamma ray detector.
 24. The method ofclaim 22 wherein the at least one gamma detector further comprises apair of gamma ray detectors on substantially opposite sides of thedownhole assembly.
 25. The method of claim 23 further comprising using adrill bit coupled to the downhole assembly for penetrating a formationand using measurements from said at least one gamma ray detector fordetermining a relative inclination of the borehole to a formationboundary.
 26. The method of claim 24 further comprising using a drillbit coupled to the downhole assembly for penetrating a formation andusing measurements from said pair of gamma ray detectors for determininga relative inclination of the borehole to a formation boundary.
 27. Themethod of claim 18 wherein said directional evaluation device furthercomprises a resistivity device,
 28. The method of claim 18 wherein saiddirectional formation evaluation device further comprises a densitymeasurement device.
 29. The method of claim 21 further comprising usinga processor for determining from said series expansion an indication ofproximity to a bed boundary in the subsurface formation. 30.-32.(canceled)
 33. An apparatus for determining a parameter of interest of amedium proximate to a borehole; the apparatus comprising: (a) abottomhole assembly (BHA) conveyed in the borehole; (b) an orientationsensor which obtains information about a tool-face angle of he BHAduring rotation thereof; (c) a directionally sensitive evaluation devicewhich obtains measurements indicative of the parameter of interest; and(d) a processor which represetnts the directionally sensitivemeasurements by a series expansion that includes a sinusoidal variationwith the toolface angle.
 34. The apparatus of claim 33 furthercomprising a drilling tubular which conveys the BHA into the borehole.35. The apparatus of claim 33 wherein the orientation sensor is selectedfrom (i) a gyroscope, (ii) a magnetometer, and (iii) an accelerometer.36. The apparatus of claim 33 wherein the directionally sensitiveevaluation device is selected from (i) a gamma ray detector, and (ii) aresistivity sensor.